1. Field of the Disclosure
Embodiments disclosed herein relate generally to oilfield components and equipment used during oil and gas production. Specifically, embodiments disclosed herein relate to a method of heat treating oilfield components.
2. Background Art
A variety of designs exist for the drilling and production of hydrocarbons, including onshore and offshore drilling and production units. Offshore drilling and production unit designs may vary based upon water depth and the type of platform used, such as floating platforms, semi-submersible platforms, tension leg platforms, spar-type platforms, and others as are known in the art. Offshore units also vary in the type and location of control devices, including wet-tree systems, where the control devices are located atop a wellhead on the sea floor, and dry-tree systems, where the control devices are located on the platform.
Components used during the drilling and production of oil wells, regardless of the location and design, are subject to corrosion, wear, and fatigue. For example, with respect to offshore drilling and production, components and equipment used are subject to a dynamic environment, where near-surface and sub-surface currents may impart bending, tension, and/or rotational stress. In a typical deepwater offshore production, for example, a riser extends between a floating platform, at the surface of the ocean, and the wellhead, at the sea floor. Because the wellhead is statically located at the sea floor and the riser and the platform or drilling rig are motive, the imparted stresses may fatigue production components, including buoyancy devices, stress-relief subs, pad-eye connections for ballast or tension lines, stress joints, blowout preventers (“BOPs”), well control assemblies, mud lift modules, ballast weights, and other components known in the art. Each of these components, including the connections at the platform, the riser joints, and the wellhead components, may experience stress and strain associated with the dynamics of the offshore environment.
As another example of components subject to wear, corrosion, and fatigue, “rod” pumps are often used during the production of oil and gas from a reservoir. This deep well pump is mechanically activated by a walking beam pumping unit which is connected by one end to a power source and by the other end to a string of steel rods (e.g., sucker rods) that interconnect themselves to form a string of rods extending to the inside of the well, with the string connected by its other end to the deep well pump. During pumping, the string of rods performs a reciprocating or rotating movement, which may produce deflections of the string. The sucker rods are thereby subjected to wear due to frictional contact with the inner wall of the production tubing. Even though the fluid environment serves as a lubricant, abrasion does occur over the surface of the sucker rods. Additionally, tools used during assembly, such as those used for centering the string, may cause tearing of the rod surface. In the case of hydrocarbon wells, the fluid includes dissolved salts and undissolved minerals which may have an additional abrasive effect on the rod surface. At the same time that abrasion occurs, the metal in the sucker rods is subjected to a hard corrosive attack caused by downhole chemicals. These rods also experience very high cyclic axial tension over their service life and may be subject to axial fatigue.
In addition to the dynamic, abrasive, and corrosive stresses briefly described above, oilfield components may also be subject to fatigue due to the high pressures and temperatures encountered during the drilling and production process. The process of drilling wells involves penetrating a variety of subsurface geologic structures, or layers called “formations.” Occasionally, a wellbore will penetrate a formation having a formation pressure substantially higher than the pressure maintained in the wellbore. When this occurs, the well is said to have “taken a kick,” The pressure increase associated with the kick is generally produced by an influx of formation fluids (which may be a liquid, a gas, or a combination thereof) into the wellbore. The relatively high pressure kick tends to propagate from a point of entry in the wellbore uphole (from a high pressure region to a low pressure region). The normal operating pressures and the high pressure kicks subject the oilfield components to additional fatigue.
In the past, oilfield components subject to fatigue loading conditions were manufactured from a single metallic alloy. The alloys normally utilized are generally low-alloy steels processed by heat treatment to the mechanical properties suited to the loading conditions. The use of a high strength nickel-based alloy in the manufacture of these parts would normally be cost prohibitive.
In many cases, these oilfield components may need to meet the design criteria for metallic oil and gas field components, such as those requirements established by NACE International (formerly the National Association of Corrosion Engineers) and the European Federation of Corrosion for the performance of metals when exposed to various environmental compositions, pH, temperature, and H2S partial pressures. For example, NACE MR0175 limits the maximum hardness of the parts to Rockwell C 22 or Brinell 237 for low-alloy steels in the quenched and tempered condition.
For most low-alloy steels, the maximum yield strength that they are able to reach under the NACE maximum hardness limitation is about 80,000-90,000 psi. Very few low-alloy steels are able to develop this yield strength and hardness combination in a section thickness having any useable significant size. For example, when the section thickness is more than four to six inches, many low-alloy steels cannot develop the desired mechanical properties on quench and temper throughout their entire section thickness at the time of heat treatment.
Since fatigue life may be affected by the amount of stress imposed on a material relative to its yield strength, many materials exhibit a shorter life in fatigue when the stress applied exceeds as low as 50% of its yield strength. Consequently, if the parts are used in fatigue loading conditions such as those defined in NACE MR0175, the allowable applied stress may be limited to 50 to 65 ksi or less.
If fatigue failure occurs at these stress levels, there is little that may be done other than to reduce the applied stress by reducing the load on the part. Because the mechanical strength of the alloy cannot be increased significantly without exceeding the maximum hardness value mandated by NACE MR0175, reducing the applied stress was the only solution formerly available. Furthermore, fatigue strength is dependent on ductility as well. Thus, because ductility and strength are inversely related material properties, raising the strength of a material to accommodate fatigue properties may be counterproductive.
Fatigue failure is a phenomenon that results from high tensile stress at the surface or within close proximity to the surface of a material. Therefore, surface modification procedures, such as shot peening, case hardening by nitriding or carburizing, and flame hardening or induction hardening, have been used to increase the fatigue strength of a material by leaving a residual compressive stress at the surface. Parts that contain a residual compressive stress at their surface are less likely to fail in fatigue since cracking is more difficult to initiate and/or propagate when the part is residually loaded in compression.
While these surface modification procedures may aid in reducing or eliminating fatigue failures, shot peening and nitriding are superficial while carburizing and flame or induction hardening generally are not capable of modifying the material properties to depths below the surface of more than approximately 0.050 inches. Furthermore, these surface modification methods may be at odds with or violate the requirements of NACE MR0175 for use of the equipment in sour service or seawater environments. For example, the hardness induced on the surface or near subsurface of a part may be in excess of the threshold value for sulfide or chloride stress corrosion cracking.
As mentioned above, the lifespan of an oilfield component may also be affected by corrosion, such as by exposure to H2S. For many years, parts in the oil tool industry have been clad overlaid on the ring grooves, sealing areas, and wetted surfaces solely for the prevention of damage to the base metal from the well bore fluid. For example, U.S. Pat. No. 6,737,174 discloses a sucker rod having a surface coated by a copper alloy. In other clad overlay processes, a corrosion resistant alloy (“CRA”) clad layer, such as nickel based Alloy 625 (i.e., INCONEL 625) has been applied in thicknesses nominally from 0.060 to 0.187 inches to protect a base metal from corrosive attack. Other CRAs may be used in these applications, but the industry has essentially standardized Alloy 625 for CRA cladding of oil tool equipment. There has been little if any attention paid to the strength of the cladding material except to assure that the strength of clad layer material is equal to or greater than the strength of the base metal in the part.
Oilfield components and parts having an increased service life are desired, including parts subject to high temperatures, corrosive fluids, high stress levels, and/or fatigue loading conditions, including cyclic loading conditions. Accordingly, there exists a need for oilfield components that have improved performance under various extreme operating conditions, including fatigue loading conditions.
In the prior art, ram and annular BOP bodies, as well as accessory equipment, have typically been manufactured for use in operating pressures up to 15,000 psi and temperatures up to 250° F. Examples of annular blowout preventers are disclosed in U.S. Pat. Nos. 2,609,836 and 5,819,013, each of which is incorporated herein by reference in their entireties. Examples of ram type blowout preventers are disclosed in U.S. Pat. Nos. 6,554,247, 6,244,560, 5,897,094, 5,655,745, and 4,647,002, each of which is incorporated herein by reference in their entireties. These BOP bodies may be manufactured using one-piece, rough machined, and heat treated low-alloy steel forgings or multiple piece low-alloy steel forgings that have been rough machined, heat treated and fabrication welded together. Castings have been and still may be used for the manufacture of these ram BOP bodies for these service conditions as well as forgings.
In the prior art, one-piece single, dual, or triple ram BOP bodies, which may be produced from low-alloy steel Grade F22, are quenched and final-tempered to meet the final material specification requirements. Alternatively, fabricated BOP bodies may be fabricated by welding together low-alloy steel Grade 8630 Modified quenched and final-tempered parts. The bodies are then machined to near net shape and weld overlaid with a corrosion resistant alloy, such as, AISI 316 austenitic stainless steel or nickel base Alloy 625 in the API ring grooves, bonnet faces and internal top seal area and other areas designated on the engineering drawings.
After fabrication welding and/or overlay welding, the BOP bodies are conventionally given a post-weld heat treatment (“PWHT”) at a temperature dependant on the steel grade from which the parts have been produced. The purpose of the PWHT is primarily to reduce the hardness of the heat affected zone (“HAZ”) of welded areas to the maximum hardness levels mandated by NACE MR0175 of HRC 22 or Brinell 237 for resistance to sulfide stress corrosion cracking (“SCC”).
This PWHT is mandated by the controlling welding specification, ASME Section IX, to be performed at a temperature below the tempering temperature of the base metal itself. The PWHT operation tends to reduce the mechanical properties of the base metal and limits the number of times that a particular BOP body can be welded and post-weld heat treated before the mechanical properties of the base metal have been degraded to a level below the minimum requirements for the base metal required for the part. After the PWHT operation has been performed, the bodies are then finish machined to their final dimensional configuration.
As detailed in the current disclosure, the prior art manufacturing procedure may be changed to use a high strength, age hardenable, corrosion resistant alloy, CRA, to selectively reinforce areas of the one piece body for encapsulation of the high surface or near subsurface stresses in the BOP body. This change may allow manufacture of BOP bodies for use at operating pressures above 15,000 psi and at operating temperatures up to 350° F. and above.
However, if the prior art method of manufacture were used, as described above, the PWHT temperature would be sufficient to obtain the required maximum HAZ hardness value but the PWHT temperature would be too low to obtain the required mechanical properties in the age hardenable CRA overlay material. If the PWHT temperature were increased to obtain the mechanical properties in the CRA overlay material, the PWHT temperature would equal or surpass the tempering temperature of the Grade F22 base material of the BOP body, which is prohibited by ASME Section IX.
For example, where the CRA filler metal for the clad overlay weld deposition is INCONEL 725 and the base material is Grade F22 low-alloy steel, the Grade F22 steel must be post-weld heat treated at a minimum temperature of 1150° F. (621° C.) for a period of time ranging from four to eight hours or more. The Grade F22 low-alloy steel with section thickness of eight inches and greater will be quenched and tempered to develop a minimum yield strength of 85,000 psi. To develop this minimum yield strength requires a tempering temperature of 1150° F. to 1250° F. (621° C. to 677° C.) for a period of time of eight to ten hours or more. However, since the INCONEL 725 is an age hardenable alloy, in order to develop its mechanical properties on the order of 120,000 psi minimum yield strength, it must be aged at a temperature of 1200° F. (649° C.) for a minimum period of time of eight to twenty four hours. All of these various tempering temperatures and times, PWHT temperatures and times, and the age hardening temperatures and times may be in conflict with one another.
If the base metal is conventionally quenched and final-tempered as described above, the age hardening temperature and time for the INCONEL 725 would further temper the Grade F22 base metal, likely lowering its mechanical properties below the minimum specification requirement. If the INCONEL 725 weldment joint on the Grade F22 were PWHT as described above, the maximum HAZ hardness would be met and the mechanical properties of the Grade F22 would be preserved, but the INCONEL 725 weld metal would likely not develop the mechanical properties in the overlay that are desired.
Accordingly, there exists a need for methods of manufacture to obtain parts meeting the requirements for HAZ hardness and mechanical properties for both the base metal and the clad overlay for use in oilfield service.